pg&e corporation 2019 third quarter earnings · •$3.2b of wildfire investments excluded from...

2019 THIRD QUARTER EARNINGSNovember 7, 2019

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Forward Looking Statements

This presentation contains statements regarding management’s expectations and objectives for future periods as well as forecasts and estimates regarding potential liability in connection with the 2018 Camp fire and 2017 Northern California wildfires, the AB 1054 Wildfire Fund, the 2019 Wildfire Mitigation Plan, 2019 assumptions, 2019 IIC guidance, 2019-2023 capital expenditures, 2019-2023 weighted average ratebase, capital expenditures and ratebase assumptions, and general earnings sensitivities for 2019. It also includes assumptions regarding capital expenditures, authorized rate base, key factors affecting earnings from operations and pending items with potential earnings from operations impact. These statements and other statements that are not purely historical constitute forward-looking statements that are necessarily subject to various risks and uncertainties. Actual results may differ materially from those described in forward-looking statements. PG&E Corporation and Pacific Gas and Electric Company (the “Utility”) are not able to predict all the factors that may affect future results. Factors that could cause actual results to differ materially include, but are not limited to:• the risks and uncertainties associated with PG&E Corporation’s and the Utility’s Chapter 11 cases, including, but not limited to, the ability to develop, consummate, and implement a plan of reorganization

with respect to PG&E Corporation and the Utility, which could be adversely affected by the termination of the Exclusive Periods as to the TCC and the Ad Hoc Noteholder Committee, the ability to obtain applicable bankruptcy court, creditor or regulatory approvals, the effect of any alternative proposals, views or objections related to the plan of reorganization, potential complexities that may arise in connection with concurrent proceedings involving the bankruptcy court, the U.S. District Court, the California state court, the CPUC, and the FERC, increased costs related to the Chapter 11 cases, the ability to obtain sufficient financing sources for ongoing and future operations, the ability to satisfy the conditions precedent to financing under the debt and equity commitments to finance the Proposed Plan and the risk that such agreements may be terminated, disruptions to PG&E Corporation’s and the Utility’s business and operations and the potential impact on regulatory compliance;

• the impact of the 2018 Camp fire, 2017 Northern California wildfires, and 2015 Butte fire, including whether the Utility will be able to timely recover costs incurred in connection therewith in excess of the Utility's currently authorized revenue requirements; the timing and outcome of the remaining wildfire investigations and the extent to which the Utility will have liabilities associated with these fires; the timing and amount of insurance recoveries; the timing and outcome of the 2017 Northern California Wildfires OII and potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other law enforcement agency were to bring an enforcement action, including a criminal proceeding, and determined that the Utility failed to comply with applicable laws and regulations;

• whether the Utility can obtain wildfire insurance at a reasonable cost in the future, or at all, and whether insurance coverage is adequate for future losses or claims;• the risks and uncertainties associated with the 2019 Kincade fire;• whether the Utility will be able to obtain full recovery of its significantly increased insurance premiums, and the timing of any such recovery; • the timing and outcomes of the 2019 GT&S rate case, 2020 GRC, FERC TO18, TO19, and TO20 rate cases, 2018 CEMA, future applications for WEMA, FHPMA and FRMMA, future cost of capital

proceeding, and other ratemaking and regulatory proceedings; • the timing and outcome of future regulatory and legislative developments in connection with the potential financing of the Utility’s wildfire-related liabilities, SB 901, future wildfire reforms, inverse

condemnation reform, and other wildfire mitigation measures or other reforms targeted at the Utility;• the occurrence, timing and extent of damages in connection with future wildfires, the associated financial impact on the Utility and the potential for AB 1054 to mitigate such impact (if at all);• the outcome of the Utility’s CWSP to help reduce wildfire threats and improve safety as a result of climate-driven wildfires and extreme weather, including the Utility’s ability to comply with the targets and

metrics set forth in the 2019 Wildfire Mitigation Plan; the cost of the program, including any costs in connection with PSPS events; and the timing and outcome of any proceeding to recover such cost through rates;

• the impact of wildfires, droughts, floods, or other weather-related conditions or events, climate change, natural disasters, acts of terrorism, war, vandalism (including cyber-attacks), downed power lines, and other events, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies, and the reparation and other costs that the Utility may incur in connection with such conditions or events; the impact of the adequacy of the Utility’s emergency preparedness; whether the Utility incurs liability to third parties for property damage or personal injury caused by such events; whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events; and whether the Utility’s insurance coverage is available for these types of claims and sufficient to cover the Utility’s liability;

• the timing and outcomes of phase two of the ex parte order instituting investigation (OII), of the safety culture OII, and the locate and mark OII;• the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within the authorized levels of spending and timely recover its costs through rates, and the

extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; • the outcome of the probation and the monitorship and other investigations that have been or may be commenced in the future, and the ultimate amount of fines, penalties, and remedial and other costs

that the Utility may incur as a result;• the ability of PG&E Corporation and the Utility to continue as going concerns (as to which management and their auditors have expressed substantial doubt); and• the other factors disclosed in PG&E Corporation and the Utility’s joint annual report on Form 10-K for the year ended December 31, 2018, joint quarterly reports on Form 10-Q for the quarters ended

March 31, 2019, June 30, 2019, and September 30, 2019 and other reports filed with the SEC, which are available on PG&E Corporation’s website at www.pgecorp.com and on the SEC website at www.sec.gov.

Unless otherwise indicated, the statements in this presentation are made as of November 7, 2019. PG&E Corporation and the Utility undertake no obligation to update information contained herein. This presentation, including Appendices, and the accompanying press release were attached to PG&E Corporation’s Current Report on Form 8-K that was furnished to the SEC on November 7, 2019 and is also available on PG&E Corporation’s website at www.pgecorp.com.

3See the Forward Looking Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions.

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Initial Contribution: PG&EInitial Contribution: Other IOUsAnnual Contribution: PG&EAnnual Contribution: Other IOUsNon-bypassable Charge

Wildfire Fund Contribution Treatment

• Contribution amounts expected to be amortized based on an assumed ~10-year life (3)

• Tax treatment pending private letter ruling from the IRS

PG&E Pre-Emergence Wildfire Liabilities

• For fires occurring after July 12, 2019 and prior to exiting Chapter 11

• Claims in excess of $1B are eligible for recovery and the fund will pay no more than 40% of allowed claims

• Balance of claims addressed through Chapter 11 process

• May seek payment for claims after funding initial contribution

PG&E Investments and Liability Cap

• $3.2B of wildfire investments excluded from earning a ROE

• $2.3B liability cap (20% of Equity T&D Rate base for 2019)

AB 1054 Wildfire Fund

$107M/year

$193M/year

$2.7B

$4.8B

$10.5B

(2)(2)

1. Participation in the AB 1054 Wildfire Fund is subject to numerous terms and conditions. As a result of post-petition wildfires, including the 2019 Kincade Fire, PG&E's ability to satisfy such conditions could be impaired.

2. Assumes annual IOU contributions will be made for a 10-year period.3. The useful life of the Wildfire Fund is estimated based on various assumptions, including the number and severity of catastrophic fires within the participating electric utilities’ service territories during the term of

the Wildfire Fund, historical fire-loss data, the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims will be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the level of future insurance coverage held by the electric utilities, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period.

$21B Wildfire Fund

(1)

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Wildfire Mitigation Highlights

Line Miles Patrolled 56,800 miles

Outage Duration (avg) 44 hours

Peak Wind Gusts 50 to 100+ mph

80180

2019 20200

100

200

Enhanced data gathering and analytics provides for:

• Highlighting areas of greatest fire spread risk and asset health

• Greater precision for refining outage impacts

• Prioritizing enhanced vegetation management and system hardening

� 6 PSPS Events � 1.0M+ Customer Impacts (1) � 300+ Damages and Hazards

Data-Driven Decision Making

Weather and Fuel Data (billions)

Fire Risk Forecasting Precision

Minimize Impact on Customers

• System Sectionalization: Up to 30% reduction in impacted customers

• Power Continuity: Four temporary microgrids to support impacted communities

• Temporary Generation: Provided 80 temporary generation deployments peaking at ~65MW for the October 26-29 PSPS event

Minimize Risk of Catastrophic Fires

• Satellite Fire Detection: State-of-the-art satellite fire detection and alert tool providing 1-5 min rapid insights

• Fire Spread Model: Leverages weather forecast models and satellite GIS data to run millions of fire spread simulations daily

• Alternative Technologies: Rapid Earth Fault Current Limiter Pilot, Enhanced Wires Down Detection Project, and other emerging technologies

Oct 26 - Nov 1 PSPS Event (2)

150+ instances of damages and hazards

2 km

2 km

2020

12 k

m

12 km

Pre-2016 (3)

1. Number of customer impacts reflects unique customers across the 2019 PSPS events.2. PSPS Reports to the CPUC can be found at www.pge.com/PSPS.3. PG&E's PSPS Program began in 2018. The pre-2016 modeling resolution refers to PG&E's previous meteorological modeling systems.

3 km

3 km

2019

2019 PSPS Key Facts

PSPS Restoration and Repair Recent Enhancements

http://www.pge.com/PSPS


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System Hardening & Resiliency

150 highest risk miles69%

hardened

Stronger and more resilient poles and covered power lines (# of Line Miles)

Enhanced Operational Practices

287 Reclosers100%

completed

Expanded Automation (# of Reclosers)

Enhanced Inspections

Transmission – Visual (# of Structures)

49,760 structures100% inspected

100% inspected

Distribution (# of Poles)

694,250 poles

100%inspected

Substation (# of Sites)

200 substations

99%inspected

Transmission – Aerial (# of Structures)

49,760 structures Vegetation Management

Enhanced vegetation management (# of Miles)

2,450 mi40%cleared

400 Stations104% completed

Weather Stations (# of Stations)

Enhanced Situational Awareness

71 Cameras132%

completed

High-Definition Cameras (# of Cameras)

2019 Wildfire Mitigation Plan Progress

Ongoing ProgramsCompleted Programs

(1) (2)

1. Reflects 2019 Wildfire Mitigation Plan progress in Tier 2 and Tier 3 high fire threat districts as of October 5, 2019.2. Wildfire mitigation cost recovery related to transmission are contingent on FERC approval, and all other costs are contingent on CPUC approval. 2019 spend reflects the mid-point of proposed range of costs as

outlined in the February 6, 2019 Wildfire Mitigation Plan submitted to the CPUC with the exception of the Enhanced Inspection program, which has mid-point forecasts of ~$800M (OpEx) and ~$700M (CapEx), and the Expanded PSPS and Enhanced Vegetation Management programs, which have updated mid-point forecasts of ~$70M (OpEx) and ~$450M (OpEx), respectively.

3. Pursuant to AB 1054, PG&E Corporation and the Utility will not earn an equity return on approximately $3.2B of fire risk mitigation capital expenditures included in the Utility’s approved wildfire mitigation plans.

YTD Progress Remaining

2019 Forecast Spend Year-To-Date SpendExpense ~$1.4B ~$1.1BCapital ~$1.1B(3) ~$0.6B

6Non-GAAP earnings from Operations is not calculated in accordance with GAAP and excludes items impacting comparability. See Appendix 1, Exhibit A for a reconciliation of Earnings per Share ("EPS") on a GAAP basis to Non-GAAP Earnings per Share from Operations and Exhibit G for the use of non-GAAP financial measures.

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Q3 2019 Earnings Results

Q3 YTD 2019

(in millions, except per share amounts) Earnings EPS Earnings EPSPG&E Corporation’s Loss on a GAAP basis $ (1,619) $ (3.06) $ (4,039) $ (7.65)

Items Impacting Comparability:

2017 Northern California wildfire-related costs 1,465 2.77 2,935 5.56

2018 Camp fire-related costs 408 0.77 1,979 3.75

2019 GT&S capital disallowance 193 0.37 193 0.37

Electric asset inspection costs 88 0.17 437 0.83

Chapter 11-related costs 55 0.10 210 0.40

PG&E Corporation’s Non-GAAP Earnings from Operations $ 590 $ 1.11 $ 1,715 $ 3.25

Items Impacting Comparability (in millions, pre-tax) Q3 YTD 20192017 Northern California wildfire-related costs $ 2,034 $ 4,075

2018 Camp fire-related costs 567 2,748

2019 GT&S capital disallowance 237 237

Electric asset inspection costs 121 606

Chapter 11-related costs 73 256

Note: Amounts may not sum due to rounding.

7Non-GAAP earnings from Operations is not calculated in accordance with GAAP and excludes items impacting comparability. See Appendix 1, Exhibit A for a reconciliation of Earnings per Share ("EPS") on a GAAP basis to Non-GAAP Earnings per Share from Operations and Exhibit G for the use of non-GAAP financial measures.

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Q3 2019 Quarter over Quarter Comparison

Non-GAAP Earnings per Share from Operations

$1.11

Q3 2018Earnings from

Operations

Vegetationmanagement

costs

Resolution of2018

regulatoryitems

Increase inshares

outstanding

Timing oftaxes

Miscellaneous Growth in ratebase

earnings

Liabilityinsurancepremiums

Q3 2019Earnings from

Operations

$0.00

$1.00

$0.25

$0.50

$0.75

$1.25($0.09)

($0.03)($0.03) ($0.01)

$0.13$0.05

($0.04)

$1.13


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2019 Assumptions

Capital Expenditures($ millions)

2019 General Rate Case $4,700

Gas Transmission and Storage 800

Transmission Owner 1,700

Total Cap Ex ~$7.2 billion

Authorized Ratebase* (weighted average)($ billions)

Equity Ratio: 52% (1) Return on Equity: 10.25%

2019 General Rate Case $27.7

Gas Transmission and Storage (2) 4.5

Transmission Owner 8.1

Total Ratebase $40.3 billion

Key Factors Affecting Earnings from Operations - Higher financing costs including DIP and pre-petition trade payables

- Incremental wildfire risk mitigation costs

- Insurance premiums, net of regulatory cost recovery

+ Incentive revenues, efficiencies and other benefits

2019 Expected Earnings below Authorized of ~200M (after-tax)(3)

If interest on pre-petition financing debt and trade payables is not recorded in 2019

Then: 2019 Expected Earnings below Authorized of ~50M (after-tax)(4)

Note 1: Due to the net changes recorded in connection with the 2018 Camp fire and the 2017 Northern California wildfires as of December 31, 2018, the Utility submitted to the CPUC an application for a waiver of the capital structure condition on February 28, 2019. The waiver is subject to CPUC approval.Note 2: GT&S authorized ratebase updated to reflect the CPUC final decision in the 2019 GT&S rate case.Note 3: Assumes pre-petition interest expense is recorded at the contractual rate in 2019, net of AFUDC.Note 4: Reflects the Utility not to meeting the requirement to record pre-petition interest expense, net of AFUDC, in 2019.

* Base earnings plan assumes CPUC-currently authorized return on equity across enterprise

Changes from prior quarter noted in blue


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($ millions, pre-tax)

2017 Northern California wildfire-related costs $ ~ 4,110

2018 Camp fire-related costs ~ 2,780

Electric asset inspection costs 700 - 900

Chapter 11-related costs ~ 550 - 600

2019 GT&S capital disallowance ~ 240

PSPS customer bill credit ~ 90

Estimated 2019 Items Impacting Comparability Guidance Total $ ~ 8,470 - 8,720

2019 Items Impacting Comparability Guidance

(1) 2017 Northern California wildfire-related costs reflect estimated third-party claims, legal, and other costs associated with the 2017 Northern California wildfires. (2) 2018 Camp fire-related costs reflect estimated third-party claims, Utility clean-up and repair, legal, and other costs associated with the 2018 Camp fire. (3) Electric asset inspection costs represent estimated incremental costs to complete enhanced and accelerated inspections of electric transmission and distribution assets and certain resulting repairs that are not probable of recovery. (4) Chapter 11-related costs include estimated external legal, financing and other fees, net of interest income, directly associated with PG&E Corporation’s and the Utility’s Chapter 11 cases. Exit financing is subject to bankruptcy court approval. (5) 2019 GT&S capital disallowance reflects pipeline-replacement costs disallowed in the 2019 GT&S rate case as a result of spending above amounts authorized in the 2015-2018 GT&S rate case period. (6) PSPS customer bill credit represents a one-time bill credit for customers impacted by the October 9, 2019 Public Safety Power Shutoff (PSPS) event.

See Appendix 1, Exhibit E for PG&E Corporation's 2019 Items Impacting Comparability Guidance and Exhibit G for Use of Non-GAAP Financial Measures.

(1)

(2)

(3)

(4)

(5)

(6)



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General Rate Case (2) Gas Transmission & Storage Electric Transmission Owner System Hardening Range

2018 Recorded 2019 Currently AuthorizedCapEx

Incremental GRCRequests and Other

Incremental TORequest

Authorized PlusRequested CapEx

Capital Expenditures Forecast

Range of ~$5.7B to ~$7B annually from 2020-2023

2018-2023 Capital Expenditures

$6.6B~$7.2B

~$5.7BWildfire Mitigation Plan: ~$900M

Other GRC and Separately Funded: ~$200M

$0.2B ~$7B~$1.1B

(1)

(3) (4)


1. PG&E is in the process of preparing a five-year financial forecast, including projected capital expenditure assumptions, in connection with the Chapter 11 proceedings. While PG&E is currently evaluating capital expenditure assumptions, amounts may materially increase from the current forecast.

2. General Rate Case spend includes transportation electrification.3. PG&E is planning to spend, primarily through its wildfire mitigation plan, at levels that are higher than currently authorized in its approved rate cases.4. Reflects updates to capital spend consistent with the Joint Comparison Exhibit in the 2020 GRC that PG&E filed on November 1, 2019.


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Expected Ratebase Growth

General Rate Case Gas Transmission & Storage Electric Transmission Owner Range

2018 2019 2020 2021 2022 2023

~7 - 8.5 %CAGR

2018-2023 Weighted Average Ratebase

$36.6B~$40.3B

~$44.5-45.5B~$47.0-49.0B

~$49.5-52.5B~$52.0-56.0B

(1) (2)

(3)

(5) (4)

1. Weighted average ratebase reflects the estimated impacts from the Tax Cuts and Jobs Act and the $240M disallowance by the CPUC in its final decision for the 2019 GT&S rate case.2. PG&E is in the process of preparing a five-year financial forecast, including projected capital expenditure assumptions, in connection with the Chapter 11 proceedings. While PG&E is

currently evaluating capital expenditure assumptions, amounts may materially increase from the current forecast. Ratebase does not reflect the reduction of $3.2B of fire risk mitigation excluded from earning a ROE, pursuant to AB 1054.

3. General Rate Case spend includes transportation electrification.4. Includes $400M for 2011-2014 spend subject to audit added in 2020. 5. Includes ~$600M related to enhanced inspections and restoration work in 2019 that have not been authorized by the CPUC or FERC. The Utility is not currently earning a return on these

amounts.



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Cap Ex and Ratebase Assumptions

Base Case Assumptions

(1) Represents Wildfire Mitigation Plan system hardening at proposed spending levels.

Potential Future Updates• 2020 and 2023 GRC rate cases

• 2022 Gas Transmission & Storage rate case

• 2018, 2019, 2020 and future Transmission Owner rate cases

• Wildfire mitigation investments

• Future transportation electrification

• Future storage opportunities

• Plan of Reorganization

EV Phase 2

TO20 Filing

TO17 Settlement

2020 GRC Filing (including Wildfire Mitigation Plan) (1)

2021

General Rate Case L

H

2017 GRC Decision

Gas Transmission & Storage L

H 2019 GT&S Decision

2019 GT&S Decision

Transmission Owner L

H

Light-Duty EV Infrastructure L&H EV Phase 1

L&H SB350SB350

Approved Pending and future filings

2020 2021 2022 2023

Appendix

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Table of Contents

Appendix 1 - Supplemental Earnings Materials Slides 15-33

Appendix 2 - Overview of Regulatory Cases Slides 34-37

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Appendix 1 – Supplemental Earnings Materials

Exhibit A:Reconciliation of PG&E Corporation's Consolidated Loss Attributable to Common Shareholders in Accordance with Generally Accepted Accounting Principles ("GAAP") to Non-GAAP Earnings from Operations

Slides 16-19

Exhibit B: Key Drivers of PG&E Corporation's Non-GAAP Earnings per Common Share ("EPS") from Operations Slide 20

Exhibit C: Operational Performance Metrics Slides 21-22

Exhibit D: Sales and Sources Summary Slide 23

Exhibit E: PG&E Corporation's 2019 Items Impacting Comparability Guidance Slides 24-26

Exhibit F: 2019 General Earnings Sensitivities Slide 27

Exhibit G: Use of Non-GAAP Financial Measures Slide 28

Exhibit H: GAAP Net Loss to Non-GAAP Adjusted EBITDA Reconciliation Slide 29

Exhibit I: Expected Timelines of Selected Regulatory Cases Slides 30-33

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Exhibit A: Reconciliation of PG&E Corporation's Consolidated Earnings (Loss) Attributable to Common Shareholders in Accordance with Generally Accepted Accounting Principles ("GAAP") to Non-GAAP Earnings from Operations

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

EarningsEarnings per

Common Share (Diluted)

EarningsEarnings per

Common Share (Diluted)

(in millions, except per share amounts) 2019 2018 2019 2018 2019 2018 2019 2018

PG&E Corporation’s Earnings (Loss) on a GAAP basis $ (1,619) $ 564 $ (3.06) $ 1.09 $ (4,039) $ 22 $ (7.65) $ 0.04

Items Impacting Comparability: (1)

2017 Northern California wildfire-related costs (2) 1,465 31 2.77 0.06 2,935 1,639 5.56 3.17

2018 Camp fire-related costs (3) 408 — 0.77 — 1,979 — 3.75 —

2019 GT&S capital disallowance (4) 193 — 0.37 — 193 — 0.37 —

Electric asset inspection costs (5) 88 — 0.17 — 437 — 0.83 —

Chapter 11-related costs (6) 55 — 0.10 — 210 — 0.40 —

Pipeline-related expenses (7) — 9 — 0.02 — 25 — 0.05

2015 Butte fire-related costs, net of insurance (8) — 6 — 0.01 — 17 — 0.03

Reduction in gas-related capital disallowances (9) — (27) — (0.05) — (27) — (0.05)

2017 insurance premium cost recoveries (10) — — — — — (23) — (0.05)

PG&E Corporation’s Non-GAAP Earnings from Operations (11) $ 590 $ 582 $ 1.11 $ 1.13 $ 1,715 $ 1,652 $ 3.25 $ 3.19

All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 27.98% for 2018 and 2019, except for certain Chapter 11-related and 2019 GT&S capital disallowance costs, which are not tax deductible. Amounts may not sum due to rounding.

Third Quarter, 2019 vs. 2018(in millions, except per share amounts)

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(1) “Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods, consisting of the items listed in the table above. See Exhibit G: Use of Non-GAAP Financial Measures.

(2) The Utility incurred costs of $2.0 billion (before the tax impact of $569 million) and $4.1 billion (before the tax impact of $1.1 billion) during the three and nine months ended September 30, 2019, respectively, associated with the 2017 Northern California wildfires. This includes accrued charges of $2.0 billion (before the tax impact of $566 million) and $4.0 billion (before the tax impact of $1.1 billion) during the three and nine months ended September 30, 2019, respectively, related to increases in the recorded liability for third-party claims. The Utility also incurred costs of $13 million (before the tax impact of $4 million) and $54 million (before the tax impact of $15 million) during the three and nine months ended September 30, 2019, respectively, for legal and other costs.

(in millions, pre-tax)Three Months Ended September 30, 2019

Nine Months Ended September 30, 2019

Third-party claims $ 2,021 $ 4,021

Legal and other costs 13 54

2017 Northern California wildfire-related costs $ 2,034 $ 4,075

(3) The Utility incurred costs of $567 million (before the tax impact of $159 million) and $2.7 billion (before the tax impact of $769 million) during the three and nine months ended September 30, 2019, respectively, associated with the 2018 Camp fire. This includes accrued charges of $526 million (before the tax impact of $147 million) and $2.4 billion (before the tax impact of $679 million) during the three and nine months ended September 30, 2019, respectively, related to increases in the recorded liability for third-party claims. The Utility also incurred costs of $15 million (before the tax impact of $4 million) and $265 million (before the tax impact of $74 million) during the three and nine months ended September 30, 2019, respectively, for clean-up and repair. In addition, the Utility incurred costs of $25 million (before the tax impact of $7 million) and $57 million (before the tax impact of $16 million) during the three and nine months ended September 30, 2019, respectively, for legal and other costs.



Third-party claims $ 526 $ 2,426

Utility clean-up and repair costs 15 265

Legal and other costs 25 57

2018 Camp fire-related costs $ 567 $ 2,748


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(4) The Utility recorded costs of $237 million (before the tax impact of $44 million) during the three and nine months ended September 30, 2019, for pipeline-replacement costs disallowed in the 2019 GT&S rate case as a result of spending above amounts authorized in the 2015-2018 rate case period. Due to flow-through treatment related to deductible repairs, $80 million of the loss does not generate a net tax benefit.

(5) The Utility incurred costs of $121 million (before the tax impact of $33 million) and $606 million (before the tax impact of $170 million) during the three and nine months ended September 30, 2019, respectively, for incremental operating expenses related to enhanced and accelerated inspections of electric transmission and distribution assets, and certain resulting repairs that are not probable of recovery.

(6) The Utility incurred costs of $73 million (before tax impact of $18 million) and $256 million (before the tax impact of $46 million) during the three and nine months ended September 30, 2019, respectively, directly associated with PG&E Corporation’s and the Utility’s Chapter 11 Cases. This includes legal and other costs of $90 million (before the tax impact of $22 million) and $191 million (before the tax impact of $28 million) during the three and nine months ended September 30, 2019, respectively ($10 million and $92 million of legal and other costs during the three and nine months ended September 30, 2019, respectively, are not tax deductible.) The Utility also incurred $114 million (before the tax impact of $32 million) during the nine months ended September 30, 2019 for debtor-in-possession (“DIP”) financing costs. These costs were partially offset by interest income of $17 million (before the tax impact of $5 million) and $49 million (before the tax impact of $14 million) recorded during the three and nine months ended September 30, 2019, respectively.



Legal and other costs $ 90 $ 191

DIP financing costs — 114

Interest income (17) (49)

2018 Camp fire-related costs $ 73 $ 256

(7) The Utility incurred costs of $13 million (before the tax impact of $4 million) and $35 million (before the tax impact of $10 million) during the three and nine months ended September 30, 2018, respectively, for pipeline-related expenses incurred in connection with the multi-year effort to identify and remove encroachments from transmission pipeline rights-of-way.


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(8) The Utility incurred costs, net of insurance, of $9 million (before the tax impact of $3 million) and $24 million (before the tax impact of $7 million) during the three and nine months ended September 30, 2018, respectively, associated with the 2015 Butte fire. This included $9 million (before the tax impact of $3 million) and $31 million (before the tax impact of $9 million) during the three and nine months ended September 30, 2018, respectively, for legal costs. These costs were partially offset by $7 million (before the tax impact of $2 million) recorded during the nine months ended September 30, 2018 for contractor insurance recoveries.



Legal costs $ 9 $ 31

Insurance recoveries — (7)

2015 Butte fire-related costs, net of insurance $ 9 $ 24

(9) The Utility reduced the estimated disallowance for gas-related capital costs that were expected to exceed authorized amounts by $38 million (before the tax impact of $11 million) during the three and nine months ended September 30, 2018. The Utility had previously recorded $85 million (before the tax impact of $35 million) in 2016 for probable capital disallowances in the 2015 GT&S rate case. From 2012 through 2014, the Utility had recorded cumulative charges of $665 million (before the tax impact of $271 million) for disallowed Pipeline Safety Enhancement Plan-related capital expenditures.

(10) As a result of the California Public Utilities Commission’s (“CPUC”) June 2018 decision authorizing a Wildfire Expense Memorandum Account, the Utility recorded $32 million (before the tax impact of $9 million) during the nine months ended September 30, 2018 for probable cost recoveries of insurance premiums incurred in 2017 above amounts included in authorized revenue requirements.

(11) “Non-GAAP earnings from operations” is a non-GAAP financial measure. See Exhibit G: Use of Non-GAAP Financial Measures.

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Exhibit B: Key Drivers of PG&E Corporation's Non-GAAP Earnings per Common Share ("EPS") from Operations

Third Quarter 2019 vs. 2018 YTD 2019 vs. 2018

Earnings Earnings per Common Share (Diluted) Earnings Earnings per Common

Share (Diluted)

2018 Non-GAAP Earnings from Operations (1) $ 582 $ 1.13 $ 1,652 $ 3.19

Vegetation management costs (2) (46) (0.09) (78) (0.15)

Resolution of 2018 regulatory items (3) (15) (0.03) (44) (0.08)

Increase in shares outstanding — (0.03) — (0.07)

Timing of taxes (4) (8) (0.01) 7 0.01

Miscellaneous (19) (0.04) (5) 0.01

Growth in rate base earnings 68 0.13 138 0.26

Liability insurance premiums (5) 28 0.05 45 0.08

2019 Non-GAAP Earnings from Operations (1) $ 590 $ 1.11 $ 1,715 $ 3.25

All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 27.98% for 2018 and 2019. Amounts may not sum due to rounding.

(1) See Exhibit A for reconciliations of (i) earnings on a GAAP basis to non-GAAP earnings from operations and (ii) EPS on a GAAP basis to non-GAAP EPS from operations.

(2) Represents the increase in routine vegetation management costs incurred during the three and nine months ended September 30, 2019, which are not recoverable through authorized revenue requirements.

(3) Represents the impact of various regulatory matters resolved during the three and nine months ended September 30, 2018, with no similar impact in 2019.

(4) Represents the timing of taxes reportable in quarterly statements in accordance with Accounting Standards Codification 740, Income Taxes, and results from variances in the percentage of quarterly earnings to annual earnings.

(5) Represents the lower insurance premium costs during the three and nine months ended September 30, 2019, due to lower coverage renewed for excess liability and the accelerated amortization of a portion of the Utility’s liability insurance premiums during the fourth quarter of 2018 as a result of the 2018 Camp fire.


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Exhibit C: Operational Performance Metrics

2019 Performance Results YTD Actual 2019 Target Meets YTD Target (1)

Safety

Nuclear Operations Safety100.0 93.7 üDiablo Canyon Power Plant (DCPP) Reliability and Safety

Electric Operations Safety0.0 1.0

Public Safety Index

Gas and Electric Operations Safety0.7 1.0

Asset Records Duration Index

Gas Operations Safety240.0 183.0 üGas First-Time In-Line Inspection

Employee Safety1.5 1.0 üSerious Injuries and Fatalities Corrective Actions Index

Customer

Escalated Customer Complaints 10.1 12.2 üFinancial

Non-GAAP Earnings from Operations (1) 1,715 See note (2) See note (2)

See following page for definitions of the operational performance metrics. The operational performance goals set under the PG&E Corporation 2019 Short-Term Incentive Plan (“STIP”) are based on the same operational metrics and targets, except as noted in Footnote 1 below.

(1) For STIP purposes, non-GAAP earnings from operations may be further adjusted in a manner consistent with the methodology used to establish the applicable STIP target.(2) The 2019 target for non-GAAP earnings from operations is not publicly reported.

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Definitions of 2019 Operational Performance Metrics from Exhibit C

Safety

Public and employee safety are measured in four areas: Nuclear Operations Safety, Electric Operations Safety, Gas Operations Safety, and Employee Safety.

The safety of the Utility’s nuclear power operations, DCPP Unit 1 and Unit 2, is based on 11 performance indicators for nuclear power generation, including unit capability, on-line reliability, safety system unavailability, radiation exposure, and safety accident rate, as reported to the Institute of Nuclear Power Operations. The safety of the Utility’s electric and gas operations is represented by: • Public Safety Index - Measure consisting of a weighted index of two electric programs that evaluate the effectiveness of compliance activities in the Fire Index Areas: (1) Enhanced Vegetation Management (50%) and (2) System Hardening (50%).

• Gas and Electric Asset Records Duration Index (equally weighed) - Measure consisting of two indices tracking the average number of days to complete the as-built process in the system of record for electric and gas capital and expense jobs from the time construction is completed in the field or released to operations. The Gas Operations Index consists of three weighted sub-metrics: (1) Transmission (60%), (2) Station (10%), and (3) Distribution (30%). The Electric Operations Index consists of three weighted sub-metrics: (1) Transmission Line (25%), (2) Substation (25%), and (3) Distribution (50%).

• Gas First-Time In-Line Inspections - Measures the Utility’s successful completion of first-time in-line inspections of newly-constructed natural gas transmission lines.

The safety of the Utility’s employees is represented by: • Serious Injuries and Fatalities (SIF) Corrective Action Index - Index measuring (1) percentage of SIF corrective actions completed on time, and (2) quality of corrective actions as measured against an externally derived framework.

Customer Customer satisfaction is measured by:

• Escalated Customer Complaints Score - Measures the number of customer complaints escalated to the California Public Utilities Commission, per 100,000 adjusted customers.

Financial “Non-GAAP earnings from operations” (shown in millions of dollars) is a non-GAAP financial measure and is calculated as income available for common shareholders less items impacting comparability. “Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods, consisting of items listed in Exhibit A.

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Exhibit D: Pacific Gas & Electric Company Sales and Sources Summary

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2019 2018 2019 2018

Sales from Energy Deliveries (in millions kWh) 22,761 23,054 59,200 60,578

Total Electric Customers at September 30 — — 5,449,991 5,428,318

Total Gas Sales (in Bcf) 184 219 600 620

Total Gas Customers at September 30 — — 4,514,365 4,498,612

Sources of Electric Energy Deliveries (in millions kWh):

Total Utility Generation 9,164 9,319 26,353 24,056

Total Utility Net Purchases/(Sales) 3,610 4,658 3,898 18,101

Direct Access and Community Choice Aggregator Purchases 11,429 9,126 31,024 21,485

Total Electric Energy Delivered (1) 22,761 23,054 59,200 60,578

Diablo Canyon Performance:

Overall Capacity Factor (including refuelings) 0.96 1 0.91 0.92

Refueling Outage Period 9/22/19 - 9/30/19 None 2/10/19/ - 3/18/199/22/19 - 9/30/19 2/11/18 - 3/22/18

Refueling Outage Duration during the Period (days) 9 None 45 39

Please see the 2018 Annual Report on Form 10-K for additional information about operating statistics.

(1) Includes other sources/(uses) of electric energy totaling (1,442) million kWh and (49) million kWh for the three months ended September 30, 2019 and 2018, respectively, and (2,075) million kWh and (3,064) million kWh for the nine months ended September 30, 2019 and 2018, respectively.

Second Quarter, 2019 vs. 2018

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Exhibit E: PG&E Corporation's 2019 Items Impacting Comparability ("IIC") Guidance

2019 IIC Guidance (in millions, after-tax) Low High

Estimated Items Impacting Comparability: (1)

2017 Northern California wildfire-related costs (2) $ ~2,960 $ ~2,960

2018 Camp fire-related costs (3) ~2,002 ~2,002

Electric asset inspection costs (4) 648 504

Chapter 11-related costs (5) ~474 ~438

2019 GT&S capital disallowance (6) ~195 ~195

PSPS customer bill credit (7) ~65 ~65

Estimated IIC Guidance $ ~6,344 $ ~6,164

All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 27.98% for 2019, except for certain Chapter 11-related and 2019 GT&S capital disallowance costs, which are not tax deductible. (1) “Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods. See Exhibit G: Use of Non-GAAP Financial Measures.

(2) “2017 Northern California wildfire-related costs” refers to estimated third-party claims and legal and other costs associated with the 2017 Northern California wildfires. The total offsetting tax impact for both the low and high IIC guidance range is $1.1 billion.

2019

(in millions, pre-tax)Low IIC

guidance rangeHigh IIC

guidance range

Third-party claims $ ~4,020 $ ~4,020

Legal and other costs ~90 ~90

2017 Northern California wildfire-related costs $ ~4,110 $ ~4,110

Actual financial results for 2019 may differ materially from the guidance provided. For a discussion of the factors that may affect future results, see the Forward-Looking Statements.

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2019



guidance range

Third-party claims $ ~2,430 $ ~2,430

Utility clean-up and repair costs ~270 ~270

Legal and other costs ~80 ~80

2017 Northern California wildfire-related costs $ ~2,780 $ ~2,780

(3) “2018 Camp fire-related costs” refers to estimated third-party claims, Utility clean-up and repair costs, and legal and other costs associated with the 2018 Camp fire. The total offsetting tax impact for both the low and high IIC guidance range is $778 million.

2019



guidance range

Electric asset inspection costs $ 900 $ 700

(4) “Electric asset inspection costs” represents incremental operating expense related to enhanced and accelerated inspections of electric transmission and distribution assets, and certain resulting repairs that are not probable of recovery. The total offsetting tax impact for the low and high IIC guidance range is $252 million and $196 million, respectively.

2019



guidance range

Legal and other costs $ 340 $ 290

Exit financing costs ~200 ~200

DIP financing costs ~120 ~120

Interest income ~(60) ~(60)

Chapter 11-related costs $ ~600 $ ~550

(5) “Chapter 11-related costs” consists of external legal, financing, and other fees, net of interest income, directly associated with PG&E Corporation’s and the Utility’s Chapter 11 Cases, of which ~$150 million of legal and other costs are not tax deductible. The total offsetting tax impact for the low and high IIC guidance range is $126 million and $112 million, respectively. Exit financing is subject to bankruptcy court approval.


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2019



guidance range

2019 GT&S capital disallowance $ ~240 $ ~240

(6) “2019 GT&S capital disallowance” reflects pipeline-replacement costs disallowed in the 2019 GT&S rate case as a result of spending above amounts authorized in the 2015-2018 rate case period. Due to flow-through treatment related to deductible repairs, $80 million of the loss does not generate a net tax benefit. The total offsetting tax impact for the low and high IIC guidance range is $45 million.

2019



guidance range

PSPS customer bill credit $ ~90 $ ~90

(7) “PSPS customer bill credit” represents a one-time bill credit for customers impacted by the October 9, 2019 Public Safety Power Shutoff (PSPS) event. The total offsetting tax impact for the low and high IIC guidance range is $25 million.


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Exhibit F: General Earnings Sensitivities for 2019 Pacific Gas & Electric Company

Variable Description of Change Estimated 2019 Earnings Impact

Rate Base +/- $100 million change in allowed rate base +/- $5 million

Return on Equity (ROE) +/- 0.1% change in allowed ROE +/-$21 million

Share count +/- 1% change in average shares +/- $0.04 per share

Revenues or Expenses '+/- $7 million pre-tax change in at-risk revenue or expense +/- $0.01 per share

These general earnings sensitivities with respect to factors that may affect 2019 earnings are forward-looking statements that are based on various assumptions. Actual results may differ materially. For a discussion of the factors that may affect future results, see the Forward Looking Statements.

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Exhibit G: Uses of Non-GAAP Financial Measures

PG&E Corporation and Pacific Gas and Electric Company: Use of Non-GAAP Financial Measures

PG&E Corporation discloses historical financial results and provides guidance based on “non-GAAP earnings from operations” and “non-GAAP EPS from operations” in order to provide a measure that allows investors to compare the underlying financial performance of the business from one period to another, exclusive of items impacting comparability. “Non-GAAP earnings from operations” is a non-GAAP financial measure and is calculated as income available for common shareholders less items impacting comparability. “Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods, consisting of the items listed in Exhibit A. “Non-GAAP EPS from operations” also referred to as “non-GAAP earnings per share from operations” is a non-GAAP financial measure and is calculated as non-GAAP earnings from operations divided by common shares outstanding (diluted). PG&E Corporation uses non-GAAP earnings from operations and non-GAAP EPS from operations to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short- and long-term operating planning, and employee incentive compensation. PG&E Corporation believes that non-GAAP earnings from operations and non-GAAP EPS from operations provide additional insight into the underlying trends of the business, allowing for a better comparison against historical results and expectations for future performance. Non-GAAP earnings from operations and non-GAAP EPS from operations are not substitutes or alternatives for GAAP measures such as consolidated income available for common shareholders and may not be comparable to similarly titled measures used by other companies.

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Exhibit H: GAAP Net Income (Loss) to Non-GAAP Adjusted EBITDA ReconciliationPacific Gas & Electric Company

Three Months Ended September 30, Nine Months Ended September 30,

(in millions) 2019 2018 2019 2018

PG&E Corporation’s Net Income (Loss) on a GAAP basis $ (1,616) $ 567 $ (4,029) $ 32

Income tax provision (benefit) (729) 15 (1,932) (527)

Other income, net (62) (104) (199) (318)

Interest expense 52 232 215 678

Interest income (18) (14) (62) (35)

Reorganization items, net 73 — 256 —

Operating Income (Loss) $ (2,300) $ 696 $ (5,751) $ (170)

Depreciation, amortization, and decommissioning 840 759 2,433 2,257

Electric asset inspection costs 121 — 606 —

2018 Camp fire-related costs 567 — 2,748 —

2017 Northern California wildfire-related costs 2,034 43 4,075 2,275

2015 Butte fire-related costs — 9 — 24

PG&E Corporation’s Non-GAAP Adjusted EBITDA $ 1,262 $ 1,507 $ 4,111 $ 4,386

Second Quarter, 2019 vs. 2018

PG&E Corporation discloses “Adjusted EBITDA,” which is a non-GAAP financial measure, in order to provide a measure that investors may find useful for evaluating PG&E Corporation’s performance during the pendency of the Chapter 11 Cases. PG&E Corporation’s management generally does not use Adjusted EBITDA in managing its business. Adjusted EBITDA is calculated as PG&E Corporation’s net income plus income tax provision (or less income tax benefit); less other income, net; plus interest expense; less interest income; plus reorganization items, net; plus depreciation, amortization, and decommissioning; plus electric asset inspection, 2018 Camp fire-, 2017 Northern California wildfire-, and 2015 Butte fire-related costs. Adjusted EBITDA is not a substitute or alternative for GAAP measures, such as net income, and may not be comparable to similarly titled measures used by other companies. See above for a reconciliation of GAAP net income to non-GAAP Adjusted EBITDA.

Note: Amounts may not sum due to rounding.

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Exhibit I: Pacific Gas & Electric Company Expected Timelines of Selected Regulatory Cases

Regulatory Case Docket # Key Dates2019 Gas Transmission and Storage Rate A.17-11-009 Nov 17, 2017 – Application filed

Jan 4, 2018 – Prehearing Conference Mar 30, 2018 – Update testimony filed to reflect 2017 Tax Act reductions in forecasted revenue requirementApr 24, 2018 – CPUC to issue ruling on proceeding scope and scheduleJun 29, 2018 – PAO testimonyJul 20, 2018 – Intervenor testimonyJun-Jul 2018 – Public participation hearingsJun-Aug 2018 – Settlement discussionsAug 20, 2018 – Concurrent rebuttal testimonySep 17-Oct 12, 2018 – Evidentiary hearings Nov 14, 2018 – Opening BriefsDec 14, 2018 – Reply BriefsJul 16, 2019 – Proposed decision issuedAug 5, 2019 – Comments on the proposed decisionAug 12, 2019 – Reply comments on the proposed decisionSept 23, 2019 – Final decision issued

2020 General Rate Case (Phase I) A.18-11-009 Dec 13, 2018 – Application filedMar 8, 2019 – Scoping Memo Mar 25, 2019 – PG&E's Revised Testimony on Real Estate servedJun 28, 2019 – PAO testimonyJul 26, 2019 – Intervenor testimonyJul-Aug 2019 – Public participation hearingsSept 4, 2019 – PG&E rebuttal testimony dueSep 23-Oct 18, 2019 – Evidentiary hearingsNov 1, 2019 – Comparison exhibit and update testimony (if necessary)Nov 6, 2019 – Evidentiary hearing on update testimony (if necessary)Nov 15, 2019 – Opening BriefsDec 6, 2019 – Reply BriefsQ1 2020 – Proposed Decision

2020 Cost of Capital A.19-04-015 Apr 22, 2019 – Application filedMay 22, 2019 – Protests filedJun 17, 2019 – Prehearing ConferenceJul 2, 2019 – Scoping Memo Aug 1, 2019 – Intervenor testimony and Applicants' supplemental testimony on AB 1054Aug 16, 2019 – Rebuttal testimony on Intervenor testimony and testimony on supplemental testimonyAug 21, 2019 – Rebuttal testimony on supplemental testimonySept 2019 – Evidentiary Hearings Sept 30, 2019 – Opening briefsOct 9, 2019 – Reply briefsNov 27, 2019 – Proposed decisionDec 2019 – Final decision

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Regulatory Case Docket # Key DatesLocate and Mark Order Instituting Investigation I.18-12-007 Dec 13, 2018 – OII issued

Jan 14, 2019 – PG&E submitted its 30 Day ReportMar 14, 2019 – PG&E submitted its 90 Day ReportMar 22, 2019 – SED filed motion to expand scopeApr 2, 2019 – PG&E filed response to SED's motionApr 4, 2019 – Prehearing ConferenceJul 24, 2019 – SED opening testimonyJul 30, 2019 – Status conferenceAug 16, 2019 – Intervenor opening testimonySept 13, 2019 – SED and PG&E reach Settlement in principleSept 18, 2019 – PG&E reply testimonySept 27, 2019 – CUE joins PG&E/SED in Settlement AgreementOct 3, 2019 – PG&E, SED, and CUE file Motion to Adopt Settlement AgreementOct 21-22, 2019 – Evidentiary hearingsNov 4, 2019 – Parties to respond to Motion to Adopt Settlement AgreementNov 19, 2019 – PG&E, SED, and CUE to reply to responses

Safety Culture and Governance Order I.15-08-019 Dec 21, 2018 – President Picker issued ruling on next phase of the Safety Culture OIIInstituting Investigation (Phase 3) Jan 16, 2019 – PG&E submitted its initial response

Feb 13, 2019 – Opening comments submittedFeb 28, 2019 – Reply Comments dueApr 15, 2019 – Workshop on Corporate GovernanceApr 26, 2019 – Workshop on Corporate StructureMay 7, 2019 – Proposed decision issuedMay 27, 2019 – PG&E opening comments filedJun 13, 2019 – Final decision issuedJun 18, 2019 – President Picker issued ruling requesting comment on safety culture proposalsJul 19, 2019 – Opening comments filedAug 2, 2019 – Reply comments due

Transmission Owner Rate Case (TO18) ER16-2320 Jul 29, 2016 – PG&E filed TO18 rate case seeking an annual revenue requirement for 2017Sep 30, 2016 – FERC accepted TO18 making rates effective Mar 1, 2017 and establishing settlement processOct 19, 2016 – FERC settlement conferenceOct 30, 2016 – CPUC seeks rehearing of FERC's grant of 50 bp ROE adder for CAISO participationFeb 7-8, 2017 – FERC settlement conference Mar 16, 2017 – Parties reached impasse in settlement discussions Jan 2018 – HearingsOct 1, 2018 – Initial decision issuedOct 31, 2018 – Brief on Exceptions (BOE) filedNov 20, 2018 – Reply to BOE filedTBD – Final decision

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Regulatory Case Docket # Key DatesTransmission Owner Rate Case (TO19) ER17-2154 Jul 26, 2017 – PG&E filed TO19 rate case seeking an annual revenue requirement for 2018

Sept 28, 2017 – FERC accepted TO19 making rates effective Mar 1, 2018, and establishing settlement processOct 2017 and May/July 2018 – FERC settlement conferencesSept 21, 2018 – Offer of Settlement filed with FERC with motion for interim rates

Oct 9, 2018 – Chief ALJ granted motion for interim rates and authorized the implementation of the interim rates (Jul 1, 2018 for Wholesale and Jan 1, 2019 for retail) pending Commission action on settlementDec 20, 2018 – FERC approved the all-party settlement

Transmission Owner Rate Case (TO20) ER19-13 Oct 1, 2018 – Application filedNov 30, 2018 – FERC accepted TO20 filing and set interim rates effective May 1, 2019Dec 14, 2018 – FERC settlement conference

Mar 14, 2019 – FERC settlement conference

Jun 13-14, 2019 – FERC settlement conferenceAug 13-14, 2019 – FERC settlement conferenceOct 9, 2019 – First comprehensive settlement offer from Intervenors and Trial Staff

Oct 28-29, 2019 – FERC settlement conferenceNov 7, 2019 – FERC settlement phone conference - status update

Wildfire Mitigation Plan Order Instituting R.18-10-007 Feb 6, 2019 – Wildfire Mitigation Plan filed

Rulemaking Feb 13, 2019 – Wildfire Mitigation Plans presentation workshopWeek of Feb 25 – Technical workshopsFeb 26, 2019 – Prehearing Conference

Mar 13, 2019 – Intervenor commentsMar 22, 2019 – Utility reply commentsApr 29, 2019 – Proposed decisions issued on Phase 1

Jun 4, 2019 – Final decisions issued on Phase 1

Jun 14, 2019 – Phase 2 initiatedJul 30, 2019 – Utilities file reports detailing data and metrics for evaluating plan effectivenessAug 21, 2019 – Comments due

Aug 28, 2019 – Prehearing ConferenceSept 10, 2019 – IOUs submit presentations on status of 2019 WMPsSept 17-19, 2019 – SED Workshops

Oct 30, 2019 – Opening Comments and motions for evidentiary hearingsNov 13, 2019 – Reply Comments and responses to motions for evidentiary hearingsDec 2019 – Proposed Decision on Phase 2

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Regulatory Case Docket # Key Dates2017 Northern California Wildfires Order I.19-06-015 Jun 27, 2019 – OII issuedInstituting Investigation Jul 29, 2019 – PG&E to submit its initial response

Jul 29, 2019 – Immediate corrective actions response due

Aug 13, 2019 – Prehearing ConferenceAB 1054 Order Instituting Rulemaking R.19-01-017 Jul 26, 2019 – OIR issued

Aug 7, 2019 – Prehearing Conference Statements Served and Filed

Aug 8, 2019 – Prehearing ConferenceAug 14, 2019 – Scoping Memo and RulingAug 29, 2019 – Opening Comments on Scoped Issues

Sept 6, 2019 – Reply Comments on Scoped Issues Sept 23, 2019 – Proposed decision issuedOct 23, 2019 – Final decision issued

Plan of Reorganization Order Instituting I.19-09-016 Sept 26, 2019 – OII issued Investigation Oct 11, 2019 – PG&E to file and serve a response to the OII

Oct 18, 2019 – Other responses to the OII filed and servedOct 23, 2019 – Prehearing Conference

Most of these regulatory cases are discussed in PG&E Corporation and Pacific Gas and Electric Company's combined Annual Report on Form 10-K for the year ended December 31, 2018.

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APPENDIX 2 - OVERVIEW OF KEY REGULATORY CASES2020 CPUC General Rate Case

• On December 13, 2018, PG&E filed its application for its 2020 General Rate Case requesting a ~$1.1B increase in revenue requirement over 2019 authorized.

($ billions) 2020 2021 2022

Revised Revenue Requirement ~$9.52 ~$9.88 ~$10.36

• On November 1, 2019, PG&E submitted the Joint Comparison Exhibit (JCE) providing a comparison of the positions of PG&E and various Parties to the 2020 GRC. The submittal included an update to PG&E’s revenue requirement forecast reflecting all forecast updates, concessions, stipulations, and forecast errata.

– The JCE also included Cal Advocates’ updated revenue requirement increase recommendations to increases of $581M (from $503M) for 2020, $301M (from 298M) for 2021, and $332M (from $329M) for 2022.

• On November 1, 2019, PG&E submitted a brief on the application of AB 1054 to PG&E’s capital expenditures for its approved 2019 Wildfire Mitigation Plan. AB 1054 prohibits PG&E from including in its equity rate base the first $3.2B of fire risk mitigation capital expenditures. PG&E estimates that this proposal would result in additional revenue requirement reductions of $22M in 2020, $57M in 2021, and $105M in 2022.

• Assigned Commissioner: Randolph• Administrative Law Judges: Lirag, Lau


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APPENDIX 2 - OVERVIEW OF KEY REGULATORY CASES2019 CPUC Gas Transmission and Storage Rate Case

• On November 17, 2017, PG&E filed its 2019 Gas Transmission and Storage rate case. PG&E subsequently revised its request to reflect impacts from the Tax Cuts and Jobs Act as well as other forecast updates to a $184M increase over the 2018 authorized revenue requirement.

• On September 23, 2019, the CPUC issued a final decision for the 2019 GT&S Rate Case, which adopted a revenue requirement increase of $31M in 2019 to our currently authorized RRQ, and a ratebase increase of $750M in 2019 to our currently authorized ratebase. The decision removed from ratebase ~$304M on a forecast basis of pipeline replacement capital expenditures for the 2015-2018 period due to cost overruns. PG&E expects the final disallowance on a recorded cost basis to be ~$237M.

Revenue Requirement ($ billions)

2018 Authorized 2019 2020 2021 2022

PG&E Proposal ~$1.30 ~$1.48 ~$1.59 ~$1.69 ~$1.68

Final Decision ~$1.30 ~$1.33 ~$1.43 ~$1.52 ~$1.58

• On October 23, 2019, PG&E filed an application requesting the rehearing of the final decision regarding issues, such as the disallowance associated with vintage pipeline replacement, reduction in PG&E's expense forecast for in-line inspections, and establishment of a memo account for Internal Corrosion Direct Assessment.

• Assigned Commissioner: Rechtschaffen• Administrative Law Judge: Powell


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APPENDIX 2 - OVERVIEW OF KEY REGULATORY CASESFERC Transmission Owner Rate Cases

TO18 (2017 Revenues)• On July 29, 2016, PG&E filed TO18 with FERC requesting a ~$1.7B revenue requirement with an ROE of

10.90% (inclusive of 50 basis point adder)• We cannot predict when a final decision will be issued

TO19 (2018 Revenues)• On December 20, 2018, FERC approved an uncontested settlement of TO19 that relies on the outcome of

the TO18 • The TO19 revenue requirement will be determined by applying a settlement factor of 98.85% to the final

TO18 authorized revenue requirement • Revenues collected during the TO19 rate period will be subject to refund once the final revenue

requirement is determined

TO20 (2019 Revenues)• On October 1, 2018, PG&E filed its TO20 rate case requesting a conversion to formula rates, a revenue

requirement of ~$1.96B, and an ROE of 12.5% (inclusive of 50 basis point incentive adder)• On November 30, 2018, the FERC accepted the filing and established interim rates effective May 1, 2019,

and directed the parties to settlement procedures while holding hearings in abeyance

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APPENDIX 2 - OVERVIEW OF KEY REGULATORY CASES2020 Cost of Capital Filing

• On April 22, 2019, PG&E filed its application for its 2020 Cost of Capital, including a request for a 16% rate of return on equity, which would result in a $1.2 billion increase in its revenue requirement based on currently authorized rate base.

• A prehearing conference was held on June 17, 2019 and a Scoping Memo and Ruling was issued on July 2, 2019 setting the category, issues to be addressed, and schedule outlining steps toward a proposed decision in November 2019.

• On August 1, 2019, PG&E filed supplemental testimony to reflect the expected effects of AB 1054 on the Utility’s wildfire-related risk profile. PG&E proposed to revise its rate of return on equity to 12%, which would result in a $400M increase in its revenue requirement based on currently authorized rate base.

2019 Currently Authorized 2020 Requested (as revised)

Cost Capital Structure

Weighted Cost Cost Capital

StructureWeighted

Cost

Return on Common Equity 10.25% 52.0% 5.33% 12.0% 52.0% 6.24%

Preferred Stock 5.60% 1.0% 0.06% 5.52% 0.5% 0.03%

Long-Term Debt 4.89% 47.0% 2.30% 5.16% 47.5% 2.45%

Weighted Average Cost of Capital 7.69% 8.72%

pg&e corporation 2019 third quarter earnings · •$3.2b of wildfire investments excluded from...

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